One of the major objectives of open hole logging in hydrocarbon exploration wells is to evaluate the fluid and fluid flow properties of the reservoir. Properties of particular interest include the relative fluid saturation at a given capillary pressure, the fluid flow permeabilities, and the fluid viscosities. These fluid flow properties are required to assess the economics of the reserve and for field development planning, such as the number of wells, well spacing, surface facilities, pipeline facilities, etc, which will be needed for production.
At present, these reservoir fluid flow parameters are determined using a variety of different approaches, including well flow testing, formation micro-test, coring and core analysis, and inference from continuous wireline well logging measurements. Each method is a trade-off between the cost of the measurement and the accuracy and associated uncertainties in the data and analysis. One of the advantages of continuous wireline logging is that it provides continuous data over the large reservoir intervals at much lower cost. The major disadvantage of current wireline logging measurements is that the fluid flow properties of the reservoir rock are inferred from measurements on non-flowing fluids, rather than measured directly on fluid flowing in the rock.
The fluid flow permeability, κ, is defined by Darcy's law:ν=−(κ/η)∇P where ν is the flow velocity, ∇P is the pressure gradient and κ/η, is the ratio of permeability to viscosity. The latter is also known as the fluid mobility. Typically, the direct measurement of permeability is obtained by laboratory core analysis. In these laboratory measurements, the viscosity of the fluid and pressure gradient are known and the velocity is measured. The permeability is then readily derived from data fitting using the Darcy law definition of permeability.